Systems and methods for generation of hydrogen by in-situ (subsurface) serpentinization and carbonization of mafic or ultramafic rock

ABSTRACT

Apparatuses, systems, and methods are disclosed for producing and liberating hydrogen gas and sequestering carbon dioxide through sequential serpentinization and carbonation (mineralization) reactions conducted in situ via one or more wellbores that at least partially traverse subterranean geological formations having large concentrations of mafic igneous rock, ultramafic igneous rock, or a combination thereof.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional PatentApplication No. 63/203,815, filed Jul. 30, 2021, the entire contents ofwhich are incorporated herein by reference.

BACKGROUND

The environmental impact of greenhouse gases, primarily carbon dioxide(CO₂) and methane (CH₄), has been the subject of much public debate overthe past several decades. More recently, self-imposed private-sectorinitiatives and government-mandated regulations to reduce the release ofgreenhouse gases into the environment have begun to be implemented. Inaddition to the capture and/or sequestration of carbon dioxide and othergreenhouse gases to mitigate their atmospheric release, much researchand development effort has been focused on the utilization ofalternatives to fossil fuel combustion for energy production in order toreduce the amount of carbon dioxide generated and/or that must becaptured and sequestered.

Hydrogen (H₂) gas holds promise as an energy source (e.g., as hydrogenfuel or through the use of green ammonia) and chemical feedstock (e.g.,methanol, ammonia, hydrocarbon fuels) that provides little-to-nogreenhouse gas emission upon combustion. Indeed, the combustion ofhydrogen gas yields just water as a reaction product. However, hydrogengas has traditionally been produced using fossil fuels (e.g., vianatural gas/methane conversion in a steam reformer), which yields thegreenhouse gas carbon dioxide as a reaction product. For example, in thesteam-methane reforming reaction mentioned, methane is reacted withsteam (i.e., water) to produce hydrogen gas and carbon monoxide. In asubsequent water-gas shift reaction, the carbon monoxide is furtherreacted with steam to produce carbon dioxide and additional hydrogengas. The hydrogen gas is subsequently separated from the carbon dioxidethrough pressure swing adsorption, membrane separation, or another gasseparation process. Thus, most hydrogen that is produced in refineryoperations, for example, produces greenhouse gases, which must becaptured and sequestered to yield meaningful benefit.

Alternatively, hydrogen gas may be generated by the electrolysis ofwater into hydrogen gas and oxygen. The hydrogen gas is subsequentlyseparated from oxygen through pressure swing adsorption, membraneseparation, or another gas separation process. Hydrogen production viaelectrolysis, or partial pyrolysis reactions, requires a substantialamount of electricity. While at least some of the required electricityfor hydrogen production via electrolysis and/or partial pyrolysisreactions may be obtained from renewable sources (e.g., wind, solar, andhydroelectric), in practice the majority of the electricity used forhydrolysis has traditionally been, and continues to be, produced throughthe combustion of fossils fuels, which also produces greenhouse gases.

The abiotic production of hydrogen gas is known to occur in certaingeological formations, e.g., at young oceanic crust near a mid-oceanicridge, as depicted in FIGS. 1A-1D. These natural reactions occur acrossa range of environmental conditions that include variable pH, oxygenfugacity, chemical composition, and pressure. Such reactions producevariable and complex mineralogy and chemistry but do not predictablyproduce any specific combination of reaction products. In fact, asgenerally illustrated in the cross-section photograph of FIG. 2 , rockdeposits 200 that may yield abiotic hydrogen often contain complexmixtures or layers of difficult-to-extract mineral phases, or will notproduce a desired product if other competing reactions are preferredbased on in situ geochemical conditions (e.g., variable redox potential(Eh), pH, pore water composition, gas chemical composition, andtemperature). For example, the kinetics and scale of hydrogen productionis highly variable in nature and its occurrence greatly depends on pH,Eh, and other aspects of fluid geochemistry in pore spaces and atmineral surfaces. Thus, the complex kinetics of reaction phases and theoccurrence of competing reactions in natural conditions (e.g.,circumneutral pH, variable oxygen fugacity, and variable pore waterchemistry) govern the products yielded by these naturally occurringreactions. Certain geological formations and/or the rocks thereof arealso known to contain minerals that are conducive to reaction withcarbon dioxide under certain conditions to form carbonated mineralphases, e.g., carbonates.

BRIEF SUMMARY

FIG. 3 provides a map that highlights the example locations of selectedsuitable and/or robust deposits of mafic and ultramafic rock around theworld. Olivine- and pyroxene-bearing ores may be found in such maficand/or ultramafic formations. As can be understood from FIG. 3 , sourcesof mafic and ultramafic igneous rocks may be found in many locations andare quite plentiful, accounting for at least 10% of the continentalcrust of the Earth, which illustrates the global applicability ofsolutions described herein. More recently, such sources of mafic andultramafic igneous rock have garnered interest for their potentialexploitation to sequester (mineralize) carbon dioxide in carbonatemineral phases. However, despite significant prior work on carbonsequestration, there is considerable debate about the best mechanisticreactions and optimized rates for carbon mineralization. As such, theeconomic viability of in situ processes has not been fully developed norhas the hydrogen generation and carbon sequestration capacity of maficand ultramafic rocks in the subsurface been realized. Moreover,optimizing porosity, permeability, and fracture generation in thesubsurface are required to in order to achieve sufficient surface areafor reactions to reach thermodynamic completion and/or economicfeasibility.

Despite the theoretical potential for such geological formations and/orthe ores thereof to be exploited for geological hydrogen or otherproducts, and for potential carbon sequestration, the processes andkinetics of these reactions has not been rigorously evaluated noroptimized for subsurface or subterranean conditions. Further, processesfor the production of hydrogen from these geological formations in thesubsurface have not been developed. Accordingly, Applicant hasrecognized a need for systems and methods that exploit certaingeological formations and/or the ores thereof in situ to liberate and/orgenerate hydrogen from geological formations that include olivine- andpyroxene-rich ores, and in addition, sequester carbon dioxide ascarbonates.

The disclosure herein provides one or more embodiments of systems andmethods for recovery of hydrogen and sequestration of carbon dioxide viain situ engineered operations within mafic and/or ultramafic rockformations.

For example, a method for producing hydrogen gas from a geologicalformation comprising mafic igneous rock, ultramafic igneous rock, or acombination thereof may include providing a wellbore that at leastpartially traverses the geological formation, the wellbore providing apathway for injection of fluids into the geological formation andrecovery of fluids therefrom, injecting a water-based stimulant throughthe pathway provided by the wellbore and into contact with reactivesurfaces of the geological formation and, recovering a fluid compositioncomprising hydrogen gas from the wellbore via the pathway.

In some embodiments, the method may include hydraulically fracturing thegeological formation by pumping the water-based stimulant at highpressure through the wellbore and into the geological formation. In someembodiments, the water-based stimulant does not include carbon dioxide.In some embodiments, the water-based stimulant includes dihydrogensulfide. In some embodiments, the water-based stimulant has an oxygenfugacity with a negative Eh value. In some embodiments, the water-basedstimulant has a salinity of about 0.1 to 4.5 per mil sodium chloride.And in some embodiments, the water-based stimulant that is injected intothe pathway has a pH of between about 8.3 and about 11.1.

In some embodiments, the pressure proximate to the reactive surfaces ofthe geological formation is in excess of about one atmosphere (˜1 bar)and below the lithostatic pressure of the target formation. Moreover, insome embodiments, the reactive surfaces of the geological formation havea temperature of between about 60° C. and about 260° C. Alternatively,the reactive surfaces of the geological formation may have a temperatureabove about 260° C. In the latter case, the method may includeminimizing interaction of carbon dioxide with the reactive surfaces ofthe geological formation during injection of the water-based stimulant.In various embodiments, the reactive surfaces of the geologicalformation comprise one or more of fayalite, ferrosilite, or acombination thereof.

In some embodiments, the method includes evacuating fluid from thegeological formation prior to injecting the water-based stimulantthrough the pathway provided by the wellbore and into the geologicalformation.

In some embodiments, the fluid composition recovered from the wellborefurther comprises one or more redox-sensitive components from the rockformation. In some such embodiments, the method may further includeseparating the one or more redox-sensitive components from the fluidcomposition recovered from the wellbore.

In various embodiments, the method may include using the fluidcomposition recovered from the wellbore as a fuel. Additionally, oralternatively, recovering the fluid composition from the wellbore viathe pathway may include storing the fluid composition proximate to thewellbore, and/or transporting the fluid composition via pipeline.

In some embodiments, the method includes injecting carbon dioxidethrough the pathway provided by the wellbore and into the geologicalformation after the fluid composition is recovered, wherein reaction ofat least a portion of the carbon dioxide with one or more of mafic orultramafic rocks in the geological formation generates at leastmagnesium carbonate or calcium carbonate. In some such embodiments, theinjected carbon dioxide comprises a mixture of water and carbon dioxide.For instance, this mixture of water and carbon dioxide may have a pH ofbetween about 4.8 and about 6.5. In addition, this mixture of water andcarbon dioxide may have a salinity of between 0.1 to 4.5 per mil sodiumchloride. Furthermore, this mixture of water and carbon dioxide maycontain nitrogen, dihydrogen sulfide, methane, or other trace gases.

In various embodiments, carbon dioxide injected into the geologicalformation may be injected at a pressure of between one bar and thelithostatic pressure of the target formation. Additionally, the carbondioxide that is injected into the geological formation may comprisesupercritical carbon dioxide or a mixture of supercritical carbondioxide and other fluids. In some embodiments, injecting the carbondioxide through the pathway provided by the wellbore is conducted aspart of a well stimulation process.

Corresponding means for performing the various method steps are setforth below.

An example system for recovery of hydrogen and/or sequestration ofcarbon dioxide via in situ engineered operations within mafic and/orultramafic rock formations may include a wellbore that at leastpartially traverses the geological formation, a source of water-basedstimulant configurable to be in fluid communication with the wellbore toallow the water-based stimulant to pass to the geological formationthrough a pathway defined at least partially by the wellbore, a fluidcontainment device positioned about an upper portion of the wellbore,the fluid containment device having one or more outlets through which afluid composition containing hydrogen gas may be recovered from thewellbore, and a source of carbon dioxide configurable to be in fluidcommunication with the wellbore to allow the carbon dioxide to pass tothe geological formation through the pathway defined at least partiallyby the wellbore.

In some embodiments, the system includes a pipeline connected to the oneor more outlets of the fluid containment device to output the fluidcomposition containing hydrogen gas that passes through the fluidcontainment device from the wellbore. The system may further include afluid storage vessel connected to the one or more outlets of the fluidcontainment device to store the fluid composition containing hydrogengas that passes through the fluid containment device from the wellbore.Furthermore, the fluid containment device may be a wellhead.

In various embodiments, the source of carbon dioxide is configurable toprovide the carbon dioxide to the wellbore at a pressure of between oneatmosphere (˜1 bar) and the lithostatic pressure of the targetformation. In some such embodiments, the provided carbon dioxide may besupercritical carbon dioxide or a mixture of supercritical carbondioxide and other fluids. In some embodiments, the carbon dioxide may bea mixture of water and carbon dioxide, and in some such embodiments, themixture may have a pH of between about 4.8 and about 6.5 and/or asalinity of between 0.1 to 4.5 per mil sodium chloride. Still further,in some embodiments the carbon dioxide may be a mixture of water andcarbon dioxide containing nitrogen, dihydrogen sulfide, methane, and/orother trace gases.

In various embodiments, the water-based stimulant may contain hydrogensulfide. This water-based stimulant may have an oxygen fugacity with anegative Eh value. In addition, the water-based stimulant may have asalinity of between about 0.1 to 4.5 per mil sodium chloride.Furthermore, the water-based stimulant may have a pH of between about8.3 and about 11.1.

In some embodiments, the system may further include fracturing equipmentconfigurable to hydraulically fracture an area of the geologicalformation proximate to the wellbore.

The foregoing brief summary is provided merely for purposes ofsummarizing some example embodiments described herein. Because theabove-described embodiments are merely examples, they should not beconstrued to narrow the scope of this disclosure in any way. It will beappreciated that the scope of the present disclosure encompasses manypotential embodiments in addition to those summarized above, some ofwhich will be described in further detail below.

BRIEF DESCRIPTION OF THE FIGURES

Having described certain example embodiments in general terms above,reference will now be made to the accompanying drawings, which are notnecessarily drawn to scale. Some embodiments may include fewer or morecomponents than those shown in the figures.

FIGS. 1A, 1B, 1C, and 1D illustrate cross-sectional representations ofyoung oceanic crust and associated structures positioned near atheoretical mid-oceanic ridge that may produce and/or host abiotichydrogen production.

FIG. 2 illustrates an example cross-section of serpentinized ultramaficrock.

FIG. 3 illustrates a map with locations of suitable olivine- andpyroxene-bearing localities throughout the world.

FIG. 4 illustrates an example wellsite proximate to a geological sourceof mafic or ultramafic igneous rock, in accordance with some exampleembodiments described herein.

FIG. 5 illustrates an example flowchart for enhancing the in situevolution of hydrogen gas from mafic or ultramafic igneous rock, inaccordance with some example embodiments described herein.

DETAILED DESCRIPTION

Some example embodiments will now be described more fully hereinafterwith reference to the accompanying figures, in which some, but notnecessarily all, embodiments are shown. Because inventions describedherein may be embodied in many different forms, the invention should notbe limited solely to the embodiments set forth herein; rather, theseembodiments are provided so that this disclosure will satisfy applicablelegal requirements.

Overview

The production of hydrogen and sequestration of carbon dioxide arecritical hurdles that must be cleared for society to transition towardsa future economy less reliant on carbon-rich fossil fuels. As notedpreviously, example embodiments described herein provide systems andmethods to do both in the same operation by applying unique stimulus tomafic and/or ultramafic igneous rock in situ in order to prompt theserpentinization reactions that generate hydrogen and the carbonationreactions that mineralize carbon. To implement various embodimentscontemplated herein requires a wellbore that at least partiallytraverses a mafic or ultramafic igneous rock formation. The wellboreprovides a pathway for the injection of fluids into the mafic orultramafic portions of the geological formation and recovery of fluidstherefrom. As described in greater detail below, a two-step reaction isutilized by example embodiments that first generates hydrogen throughthe injection of a water-based stimulant (the particular characteristicsof which are described below) into the wellbore, and then sequesterscarbon dioxide in the rock formation through the injection of carbondioxide into the wellbore for permanent storage in the rock formation.Example embodiments can achieve both meaningful hydrogen recovery andcarbon sequestration by identifying rock formations having suitablecharacteristics, subsurface depths that optimize the preferred chemicalreactions of fluids with rock, the sequencing and nature of fluidinjection and recovery, and the particular characteristics of the fluidto be injected into the rock formation.

In contrast to a strategy for ex situ generation of hydrogen andsequestration of carbon dioxide, unique mechanistic processes arerequired to optimize the economics of hydrogen generation andcommensurate sequestration of carbon dioxide in the subsurface. In an exsitu environment, sufficiently complete hydraulic stimulation and/orrock comminution can be performed that maximizes the effectiveness ofboth hydrogen-generating reactions and carbonation reactions. However,the degree of hydraulic stimulation and rock comminution that may bepossible ex situ is simply not achievable within the subsurface; hence,additional consideration is required to stage in situ operations in amanner that may not achieve perfect thermodynamic completion of eithercarbonation or serpentinization reactions, but that will still suitablyenhance porosity, permeability, and fracture generation in thesubsurface to ensure that the injections of fluids (i.e., water, carbondioxide, carbon dioxide-rich brines) will promote both hydrogengeneration and carbon sequestration at a meaningful scale and in acontrollable manner.

While other subsurface carbon sequestration strategies can injectgas-phase carbon dioxide into isolated formations, and into salineaquifers, each of these strategies has significant challenges. Withregard to the storage of fluid carbon dioxide, all such strategiescreate environmental risks and future carbon management challengesbecause any stored gas may migrate at some future time. Accordingly,carbon mineralization is a preferred mechanism of carbon sequestration(as illustrated by the significantly higher tax credit offered in theUnited States for permanent carbon sequestration in carbonate mineralsthan for other forms of storage).

However, existing carbon mineralization strategies also faceconsiderable challenges intrinsically related to the carbonmineralization process. The process of carbon mineralization produces avolumetric expansion of rock, which manifests in situ as a reduction inthe porosity, in most cases a reduction in the permeability, andalteration of the fracture characteristics (openness, aperture, porethroat size, connectivity) of fluid flow pathways in the rock, or in aworst case completely closes these fluid flow pathways. The injection ofcarbon dioxide to cause mineralization of carbon reduces the hydraulicconductivity of the rock into which the carbon dioxide is injected, andhence reduces the potential for both hydrogen generation and theremaining overall capacity to use existing subsurface wellinfrastructure for ongoing carbon sequestration. Because mafic andultramafic rocks have very low porosity and permeability to begin withand carbon mineralization in such formations further lowers porosity andpermeability, only a relatively low volume of carbon can be sequesteredusing a strategy focused only on carbon mineralization, This makes theeconomics of such strategies particularly challenging. A technique thatwould partially ameliorate the problem is the use of supercriticalcarbon dioxide, which would allow penetration of any available flowpaths to a greater degree than would be possible with carbon dioxide inany other form. Applicants use this aspect in some of their embodiments.

As such, the economic viability of in situ processes has not been fullydeveloped nor has the hydrogen generation and carbon sequestrationcapacity of mafic and ultramafic rocks in the subsurface been realized.Applicant is unaware of any prior attempts to use an optimized chemicalprocesses of hydrogen generation followed by carbon mineralization toenhance the kinetics and total volumetric capacity of in situ hydrogenproduction, reservoir fluid flow properties, or carbon sequestration.

Although a high level explanation of the operations of exampleembodiments has been provided above, specific details regarding theconfiguration of such example embodiments are provided below.

Serpentinization and Carbonation Reactions

The disclosure herein provides one or more embodiments of systems andmethods that facilitate the production of hydrogen and/or other desiredminerals through serpentinization reactions involving olivine- andpyroxene-rich ores found in mafic and/or ultramafic igneous rock.Olivine, a substantial component of both mafic and ultramafic rock, is asolid solution series of a magnesium silicate (forsterite) and an ironsilicate (fayalite). In olivine-rich deposits, fayalite is usually theminor constituent and ranges in concentration from 5% to 20% of theolivine, with the lower range concentrations occurring more commonly.Consequently, the thermochemical activity of fayalite in such depositsis relatively low compared to that of the forsterite. Nevertheless, whencompleted, the reaction produces magnetite, silica, and hydrogen (fromthe reaction of fayalite with water). Pyroxene, also a common componentof both mafic and ultramafic rock, is often composed of a solid solutionof ferrosilite and enstatite. As with fayalite, the reaction offerrosilite (5-20% of the pyroxene) with water generates magnetite,silica, and hydrogen.

Table I, provided below, gives representative serpentinization reactionsinvolving fayalite (Fe₂SiO₄), ferrosilite (Fe₂Si₂O₆), and forsterite(Mg₂SiO₄). Fayalite and forsterite are mineral phases that areassociated with olivine-rich ore and ferrosilite is a mineral phase thatis associated with pyroxene-rich ore. Under certain conditions (i.e., pHgreater than 8, low oxygen fugacity (with a negative Eh value ornegative electric potential)), water reacts with fayalite andferrosilite to generate magnetite (Fe₃O₄), silica (SiO₂), and hydrogengas (H₂) in the appropriate stoichiometric ratios. In each case, twomoles of hydrogen gas are produced from three moles of either fayaliteor ferrosilite mineral. Under other conditions (acidic or circum-neutralpH, oxidizing conditions), water reacts with forsterite to generateantigorite (Mg₃Si₂O₅(OH)₄), brucite (Mg(OH)₂), and/or a host of otheraccessory mineral phases in the appropriate stoichiometric ratios. Insuch case, zero moles of hydrogen gas are produced from the two moles offorsterite mineral, while the commensurate mineralization of carbondioxide, which is favored under these conditions, reduces porosity,permeability, and potential for fluid flow.

TABLE 1 Hydrogen-Generating Serpentinization Reactions SerpentinizationReactions Moles of Mineral Igneous Moles Mineral Phase Reaction Materialof H₂ Olivine Fayalite 3Fe₂SiO₄ + 2H₂O → 2Fe₃O₄ + 3SiO₂ + 2H₂ 3 2Pyroxene Ferrosilite 3Fe₂Si₂O₆ + 2H₂O → 2Fe₃O₄ + 6SiO₂ + 2H₂ 3 2 OlivineForsterite 2Mg₂SiO₄ + 3H₂O → Mg₃Si₂O₅(OH)₄ + Mg(OH)₂ 2 0

In one or more embodiments, the disclosed systems and methods may alsofacilitate the sequestration of gaseous carbon dioxide (e.g., ascarbonate mineral phases) through carbonation reactions involvingolivine- and pyroxene-rich ores found in mafic and/or ultramafic rock.Table II, provided below, gives representative carbonation reactionsinvolving forsterite (Mg₂SiO₄), enstatite (Mg₂Si₂O₆), anorthite(CaAl₂Si₂O₈), antigorite (Mg₃Si₂O₅(OH)₄), and brucite (Mg(OH)₂).Forsterite is a mineral phase that is associated with olivine-rich ore,enstatite is a mineral phase that is associated with pyroxene-rich ore,anorthite is a mineral phase that is associated with plagioclase-richore, antigorite and brucite are mineral phases that are associated witha serpentine-rich ore.

Carbon dioxide reacts with forsterite, enstatite, anorthite, and/orantigorite to generate at least magnesium carbonate (or at least calciumcarbonate in the case of anorthite) and silica (SiO₂) (or kaolinite(Al₂Si₂O₅(OH)₄ in the case of anorthite); these reactions are favored inacidic conditions in the presence of water and CO₂. The reaction ofantigorite and brucite with carbon dioxide further yields astoichiometric quantity of water. In the case of the carbonationreaction involving forsterite and enstatite, two moles of carbon dioxidegas are converted to magnesium carbonate per mole of either forsteriteor enstatite mineral. For the carbonization of antigorite, three molesof carbon dioxide gas are converted to magnesium carbonate per mole ofantigorite. In the case of anorthite, three moles of carbon dioxide gasare converted to calcium carbonate per mole of anorthite. Finally, thereaction of brucite with carbon dioxide yields one mole of magnesiumcarbonate per two moles of water as shown in the stoichiometric ratiosset forth in Table 2.

TABLE 2 Carbon-Sequestering Carbonation Reactions DecarbonationReactions Moles of Mineral Igneous Moles Mineral Phase Reaction Materialof CO₂ Olivine Forsterite Mg₂SiO₄ + 2CO₂ → 2MgCO₃ + SiO₂ 1 2 PyroxeneEnstatite Mg₂Si₂O₆ + 2CO₂ → 2MgCO₃ + 2SiO₂ 1 2 Plagioclase AnorthiteCaAl₂Si₂O₈ + CO₂ + 2H₂O → CaCO₃ + Al₂Si₂O₅(OH)₄ 1 1 Serpentine AsbestosMg₃Si₂O₅(OH)₄ + 3CO₂ → 3MgCO₃+ 2SiO₂ + 2H₂O 1 3 Brucite Mg(OH)₂ + CO₂ →MgCO₃ + 2H₂O 1 1

In nature, and as previously described, the above-describedserpentinization and carbonization reactions occur, but only in adifficult to predict and often chaotic mix of reactions occurringsimultaneously (or sequentially) across a range of environmentalconditions in situ based on the characteristic of fluids with variableand sometimes changing characteristics (e.g., pH, oxygen fugacity, porewater chemical composition (e.g., salinity), gas chemistry, andpressures found in nature. The multitude of reactions occurring innature produce variable and complex mineralogy and chemistry, but do notpredictably produce any specific combination of usable reactionproducts.

Applicant has recognized that despite the significant theoreticalpotential of mafic and/or ultramafic igneous rocks (i.e., olivine- andpyroxene-bearing ores, e.g., with elevated iron content), as describedabove, the processes and kinetics for serpentinization and carbonationreactions have not been rigorously evaluated nor optimized in thesubsurface for productive ends. Accordingly, such reactions havehistorically not been deployed to utilize geological sources foreconomic geological hydrogen, to be exploited as natural sources andcatalysts for hydrogen production, or for carbon sequestration.Specifically, process steps to enhance the subsurface carbonsequestration and production of hydrogen and/or other minerals fromthese types of rocks have not been developed. Further, Applicant isunaware of any prior attempts to use an optimized chemical processes ofhydrogen generation or carbon mineralization to enhance the kinetics andtotal volumetric capacity of hydrogen production, reservoir fluid flowproperties, or to enhance the capacity for additional subsurface carbondioxide mineralization.

In Situ Generation of Hydrogen and Sequestration of Carbon Dioxide

In various embodiments contemplated herein, carbon dioxide may bemineralized, and hydrogen may be produced economically (and with anoverall neutral to net-negative carbon footprint) by an engineeredsystem using olivine- and pyroxene-rich ores accessed by subsurfacedrilling and hydraulic stimulation of mafic or ultramafic rock tooptimize serpentinization and carbonation reactions. To produce theseresults, Applicant has developed an engineering process that stimulatessequential reactions that may be performed by and/or within a wellsitesystem as shown in FIG. 4 .

The illustration in FIG. 4 depicts an example engineered systemcontaining a wellsite 400 proximate to a geological formation of maficor ultramafic igneous rock. As shown in FIG. 4 , a system of componentsis arranged at the wellsite 400 to facilitate the injection of fluidsinto the geological formation and the recovery of fluids from thegeological formation. These components interact with the geologicalformation via a wellbore 402 that is drilled into the geologicalformation to permit the injection and recovery of fluids. The wellboremay be drilled in any suitable fashion, such as through the use of adrilling rig 404, as shown in FIG. 4 . A fluid containment device suchas a wellhead (not shown in FIG. 4 ) may be positioned about an upperportion of the wellbore 402 (in place of the drilling rig 404) toprovide a structural and pressure-containing interface for injection andrecovery of fluids from the wellbore 402. The fluid containment devicemay have one or more outlets through which fluids be injected orrecovered from the wellb ore 402.

The depth of the wellbore 402 may be designed based on the specificcharacteristics of the geological formation into which the wellbore 402is drilled, with the goal of drilling the wellbore 402 to a depthenabling fluid to interact with subsurface regions of the geologicalformation having suitable temperature for generation of hydrogen ormineralization of carbon dioxide.

The injection of fluids into the geological formation hydraulicallystimulates the rock, which may induce or enlarge fractures 406 withinthe rock formation proximal to the wellbore. For instance, the injectionof a water-based stimulant may prompt serpentinization and otherreactions within the reactive mineral phases of the rock. As describedpreviously, serpentinization reactions produce hydrogen and lead tochemical reactions (i.e., changes in the constituent minerals) thatmodify the crystalline structure of the rock formation in ways thatintroduce additional pore space, permeability, and hydraulicconnectivity of the geological formation proximal to the wellbore 402.Without the increase of pore volume during an initial hydrogengenerating step, the occurrence of carbon dioxide mineralizationprocesses (i.e., known to occur in natural systems) would reduce theporosity of the constituent mafic and ultramafic rocks. As anotherexample, available technologies such as directional drilling andhydraulic fracturing may be used to induce fractures, and hence increase(engineered secondary) porosity and permeability, and hence increase thesurface area suitable for reactions in the subsurface. In this regard,hydraulic stimulation (i.e., hydrofracturing) technologies may utilizefracturing equipment to hydraulically fracture the geological formationby pumping fluid, and possibly proppant, at high pressure through thewellbore 402 and into the geological formation to induce new fractures406, or to enlarge and/or sustain the fractures 406 already present inthe rock formation.

FIG. 4 further illustrates that fluid may be provided for injection intothe wellbore 402 by way of a tanker truck loaded with a fluid tank 408.The fluid tank 408 may connect via hose 410 to an outlet of the fluidcontainment device (which may in turn facilitate transmission of thefluid in fluid tank 408 through the wellbore 402 and into the targetedgeological formation). While a fluid tank 408 is shown for ease ofillustration, it will be understood that various example embodiments mayutilize a variety of different methods delivering fluid to the fluidcontainment device for injection into wellbore 402. For instance,although such fluids may be received by truck as shown in FIG. 4 ,fluids may be transmitted by a pipeline or containment pond connecting asource of fluid to the fluid containment device. Similarly, it will beunderstood that various example embodiments may be configurable toinject any of a variety of different types of fluid (e.g., brine,CO₂-rich brine, H₂S-rich brine, CO₂) into the wellbore 402 via the fluidcontainment device, such as water-based stimulants and carbon dioxide asdescribed herein, other fluids, such as fracturing fluids and/orproppants, or the like may also be injected into the rock formation viathe wellbore 402.

Finally, the wellsite 400 may host one or more fluid storage vessels412A-412N that may be configurable to connect via pipeline to the fluidcontainment device (e.g., via a pipeline) and deliver fluids to thefluid containment device for injection into the wellbore 402 or receivefluids recovered from the wellbore 402 via the fluid containment device.Fluid storage vessels 412A-412N may further connect to additionalprocessing or refining components located at the wellsite 400, or may beconnected to, or be configurable to connect to pipelines fortransmission of stored gas to a remote location away from the wellsite400. In some embodiments, fluid storage vessels 412A-412N may further beconfigurable to transmit stored gas to tankers for transportation viatruck, rail, or boat, or may in some embodiments themselves be portableand transported in such a manner. Additionally, or alternatively, therecovered fluids may be directly transmitted offsite to a remotelocation not at the wellsite 400. In some embodiments, the fluidsrecovered from the wellbore 402 may be utilized on-site as a fuel,either to power processing or refining machinery, or other energy needsat the wellsite, for the generation of heat to be applied to fluidinjected into the rock formation, or for any other suitable purpose.

Turning to FIG. 5 , a flowchart is illustrated that contains exampleoperations for the in situ generation of hydrogen and sequestration ofcarbon dioxide, in accordance with embodiments described herein. Theprocedure set forth in FIG. 5 may begin either from operation 502, wherea new well will be drilled to permit the subsequent operations of theprocedure, or from operation 508, where an existing well may berepurposed for use in example methods described herein.

Starting first at operation 502, an example method may involve locatinga geological formation including mafic or ultramafic igneous rock. Asdescribed previously, certain desired reactions that generate hydrogenand sequester carbon involve olivine- and pyroxene-rich ores found inmafic and/or ultramafic igneous rock. Olivine is a solid solution offorsterite and fayalite. In olivine deposits of interest to producehydrogen, fayalite is usually the minor constituent, ranging from 6% to20%, usually at the lower end. Pyroxene is often composed of a solidsolution series of ferrosilite and enstatite with a similar percentageof iron-bearing ferrosillite. Consequently, the potential thermochemicalactivity of both fayalite and ferrosillite as part of a solid solutionseries is relatively low compared to that of pure fayalite andferrosillite. The mixture of the minerals is almost an “ideal” solution.In an ideal solution, the thermochemical activity varies linearly withthe mole fraction and is roughly equal to the mole fraction. Thus,catalyzing a multiple step reaction that first targets one end of theolivine and pyroxene solid solution, the chemical reactivity of theresidual phase is enhanced, which further benefits the increasedactivity stemming from the incipient fractures and correspondingincrease in permeability.

Besides the characteristics of the ideal rock formations to utilize forthe engineered solutions contemplated herein, economic considerationsalso drive the identification of appropriate geological formations. Tothis end, the ideal locations for implementation of example embodimentswill have rock formations in close proximity to potential users of theproduced hydrogen gas, which may thereby provide nearby end-users ofgenerated hydrogen without the additional cost or logistics involved intransportation of hydrogen gas from a wellsite to a buyer.

Moreover, because a key driver of hydrogen generating reactions is thepresence of iron-rich mineral phases in the source rock, other rockformations besides mafic or ultramafic rock may be suitable for certainembodiments contemplated herein. For instance, reduced-iron minerals,such as pyrite, may usefully generate hydrogen when reacted with water,and thus may be suitable sites for the hydrogen generating components ofsome embodiments contemplated herein (even if such sites are notsuitable for subsequent carbon sequestration). As shown by operation504, an example method may involve the drilling of a wellbore into thelocated geological formation. The wellbore may be drilled to a depthhaving an appropriate temperature profile to catalyze and/or enhanceserpentinization reactions. For instance, the serpentinization reactionsdescribed previously are highly temperature sensitive, with thereactions starting to generate hydrogen occurring at around 60° C. andabove, and wherein the kinetic rate of the reactions is enhanced withincreasing temperatures. However, higher temperatures may not bepreferred in every embodiment contemplated herein. Above around ˜260°C., hydrogen produced in situ from the reaction of water with the sourcerock may react with carbon dioxide to produce methane in what is knownas a Sabatier reaction. Accordingly, in some embodiments the wellboremay be drilled to reach a depth where the geological formation has atemperature of between around 60° C. to around ˜260° C., especially inthe presence of CO₂, which is common and often abundant in thesubsurface. However, methane is itself a useful product, so a wellborethat extends into subsurface regions having temperatures above 260° C.may still be suitable in some embodiments in which both hydrogen andmethane can be recovered from the geological formation. Moreover,because higher temperature enhances the serpentinization reactions, itis conceivable that higher temperature settings may produce morehydrogen even though some of the produced hydrogen is reacted to producemethane. Finally, in some embodiments, the production of methane via theSabatier process may be avoided by minimizing the interaction of carbondioxide with hydrogen in the subsurface, such as by minimizing oreliminating the existence of carbon dioxide in any fluid injected intothe well during the first serpentinization/hydration step, in which casedrilling a well to a depth offering higher temperatures may also bepreferred. At these depths, it is likely that the pressure proximate tothe reactive surfaces of the geological formation will be at or inexcess of about 50 bars.

As shown by operation 506, some example methods may hydraulicallyfracture the geological formation to enhance its hydraulic connectivityand expose additional reactive surfaces. However, as noted previously,injection of a water-based stimulant into the rock formation may itselfcause sufficient increases in porosity and permeability and hydraulicconnectivity such that a precursor fracturing step may not be necessary.Either following operation 504 or optional operation 506, the proceduremay then advance to operation 510, which is described below. Inembodiments where an existing wellsite will be selected for use, theprocedure may begin from operation 508 rather than from operation 502.

In operation 508, some example methods may begin the procedure bylocating an existing well providing access to reactive surfaces of maficor ultramafic rock. For instance, certain geothermal wells may bedrilled into mafic or ultramafic formations, and may thereafter besuitable candidates for example embodiments described herein. Moreover,the same considerations involved in locating an appropriate rockformation for drilling of a wellbore may be used to identify existingwellbores that may be repurposed for hydrogen generation and/or carbonsequestration as discussed herein.

Following drilling (and possibly hydraulic fracturing) of a wellbore asdescribed in operations 504 and 506, or simply locating a suitableexisting wellbore as described in operation 508, the procedure maythereafter advance to operation 510 for the first of two artificiallyinduced rock reaction stages. Optionally, prior to performance ofoperation 510, the wellbore may be evaluated to remove latent fluidpresent in the wellbore (e.g., gas, water, brine, drilling fluid, or thelike).

As shown by operation 510, example methods involve the injection of awater-based stimulant into the pathway provided by the wellbore and intocontact with reactive surfaces of the geological formation. Reaction ofat least a portion of the water-based stimulant with one or more of thereactive surfaces of the geological formation generates hydrogen, inaccordance with the serpentinization reactions described previously.Either following hydraulic stimulation or when utilizing naturalfracture networks, the thermochemical activity and hence rates of thereaction may be enhanced by first removing fayalite by reacting thefayalite or ferrosilite with water at favorable conditions oftemperature (60° C. to 260° C.), pressure (>1 atmosphere, but typicallyabove 50 bars), gas chemical composition, pore water chemicalcomposition (e.g., salinity), pH (>8.3, but commonly above 9.5), and inreducing conditions/low oxygen fugacity (i.e., negative Eh). When thefayalite and ferrosilite drop out of the solid solution due to reactionwith water of optimized composition, the thermochemical activity of theremaining forsterite and enstatite, as well as antigorite, and/orbrucite, and/or other mineral phases produced by carbonation reactionswill increase according to their newly exposed surface area. Thus, thereactivity of the remaining forsterite and enstatite minerals willproceed at an increased rate (determined to be between 4 and 19% fasterin laboratory simulations) according to the now higher molar fraction ofthis phase in the solid solution.

In many embodiments, the water-based stimulant may intentionally notinclude carbon dioxide. By injecting the water-based stimulant into theformation without the common-in-natural-setting co-reactions of carbonmineralization prompted by the presence of carbon dioxide, operation 510creates more porosity and permeability in the rock formation itself,thereby enabling greater penetration of additional water for furtherhydrogen generation and eventually increasing the potential forincreased carbon dioxide mineralization within the newly formed porosity(up to the theoretical limit of the Fe-silicate phase (e.g., up to˜20%). This enhancement is observed because the reaction of water withfayalite and ferrosilite in the mafic or ultramafic rock produces rockstructures having volumetrically smaller crystalline structures. Forinstance, magnetite has a volumetrically smaller spinel crystalstructure that is denser (5,170 kg/m³) than that of the pre-reactionfayalite (4,390 kg/m³) or ferrosilite (3,880 kg/m³). Accordingly, theinjection of the water-based stimulant in operation 510 spurs thereaction of fayalite and ferrosilite with water, which in turn reducesthe volume of the reactive surfaces of the geological formation,increasing porosity and permeability, and hence the hydraulicconnectivity in the subsurface regions proximate to the wellbore,thereby increasing the surface area available for subsequent reactions.

Moreover, this water-rock reaction differs from the naturally occurringreactions in the subsurface in several key ways. First, the water-basedstimulant may include characteristics that do not occur in nature. Forinstance, the water-based stimulant may not comprise pure water, but mayalso include other components, such as hydrogen sulfide (0-30% by volumein the gas phase) or salts (e.g., Na, Ca, Cl, Br). Moreover, thewater-based stimulant may have an oxygen fugacity with a negative Ehvalue (i.e., negative electric potential), a pH of between about 8.3 andabout 11.1, across a range of salinity (0.1 to 4.5 per mil) sodiumchloride (NaCl). This combination of characteristics rarely occursnaturally in situ and is challenging to sustain throughout the evolutionof various geological processes. To produce water-based stimulant havinglow oxygen fugacity, the water may be sourced from groundwater,municipal wastewater, mine water, geothermal water, and/or otherwaste/process water streams which has a naturally low oxygen fugacity,or may be pre-processed to artificially induce a low oxygen fugacity(for instance, by passing the water-based stimulant through a heated bedof copper filings prior to injection into the well or otherwiseelectrically catalyzing the removal of oxygen). Moreover, the pH balanceof the water-based stimulant may be modified through the addition ofsodium bicarbonate or various hydroxides. Finally, the salinity of thewater-based stimulant may be adjusted through the addition of sodiumchloride, or other common salts (e.g., KCl).

At operation 512, a fluid composition including hydrogen, a mixture ofhydrogen with nitrogen, a mixture of hydrogen with methane, and/or amixture of hydrogen with carbon dioxide gas may thereafter be recoveredfrom the wellbore. Importantly, the molecular and isotopic compositionof hydrogen formed by in situ reactions can be determined and used toquantify the contributions from in situ hydrogen generation based onmeasurement of the in situ temperature conditions and comparison tostandard geothermometers based on the known fractionation factors (a)between H₂O and H₂. The fluid may spontaneously flow based on its ownpressure or be pumped out of the well following operation 512, and maythereafter be stored for subsequent use, further processed andtransmitted away from the wellsite, or even used as a fuel at thewellsite itself. While the generation of hydrogen has previously beendescribed as a product of the interaction between injected water-basedstimulant and the reactive surfaces of the mafic or ultramafic rock,other reactions may occur as well. For instance, depending on the fluidcomposition used during treatment, certain redox-sensitive components ofthe rock formation, such as lithium, nickel, molybdenum, cobalt, andrare earth elements (e.g., lanthanum, cerium) and uranium may bemobilized from the injection of water as described in operation 510.Because the disclosed two step fluid injection process involves changingredox (i.e., Eh, oxidizing to reducing shifts) and pH (acidic to basicshifts) conditions, various rare metals are solubilized and hencerecoverable with flowback fluids from the well. The fluid compositionrecovered from the wellbore may also contain these mobilized components,which may thereafter be further separated from the fluid compositionafter extraction from the well. Separation can be conducted usingdensity separation, membranes, or collection of gangue material.

Following operation 512, the procedure may return to operation 510 foranother round of water-based stimulant injection. Alternatively, theprocedure may advance to operation 514 as described below.

After the recovery of the fluid composition, operation 514 illustratesthat example methods may utilize the subsequent injection of carbondioxide into the pathway provided by the wellbore and into thegeological formation. The carbon dioxide may be injected at a pressureexceeding atmospheric pressures up to (but below) the lithostaticpressure (considering various safety factors)) expected for the latentpressure within the target rock formation. Reaction of at least aportion of the carbon dioxide with one or more of the forsterite,enstatite, antigorite, or brucite in the geological formation willpermanently mineralize carbon from the injected carbon dioxide into thesolid (mineralized) form of magnesium carbonate, or other carbonateminerals. In various embodiments, the injected carbon dioxide may be asupercritical carbon dioxide, and/or a fluid mixture of carbon dioxidewith water and other elements. For instance, the carbon dioxide mixturemay also contain varying proportions of nitrogen (N₂, up to at least50%) or other gases (e.g., helium (He, up to at least 1%), argon (Ar, upto at least 1%), dihydrogen sulfide (H₂S, up to at least 10%) of varyingproportion. The carbon dioxide mixture may have a pH of between about4.8 and about 6.5 and may have a salinity of (0.1 to 4.5 per mil) sodiumchloride (NaCl).

Injection of carbon dioxide prompts mineralization within the rockformation, thereby reducing porosity, permeability, and hydraulicconnectivity of the rock. Accordingly, because of the tendency of carbonmineralization to “plug” the rock formation, in some embodiments thestep at operation 514 of injecting the carbon dioxide through thepathway provided by the wellbore may be conducted as part of a wellstimulation process.

As described above, example embodiments provide methods and systems forin situ generation of hydrogen and permanent (mineralized) sequestrationof carbon dioxide.

FIG. 5 illustrates operations performed in various example embodiments.It will be understood that each flowchart block, and each combination offlowchart blocks, may be implemented by various means. The flowchartblocks support combinations of means for performing the specifiedfunctions and combinations of operations for performing the specifiedfunctions. In some embodiments, some of the operations above may bemodified or further amplified. Furthermore, in some embodiments,additional optional operations may be included. Modifications,amplifications, or additions to the operations above may be performed inany order and in any combination.

Laboratory Experiments

In a simulated implementation of a system and a method of an embodimentof the disclosure, an ultramafic ore was reacted with carbon dioxide tosequester the carbon dioxide as magnesium carbonate and water to evolvehydrogen gas. The example was conducted in three phases: 1) rockpreparation; 2) water preparation; and 3) reaction process, each ofwhich is described in greater detail below. As part of the analysis ofthe overall system and method, the composition of the ore (i.e.,forsterite, fayalite and other minerals), the reaction conditions towhich the ore was subjected, and the characteristics of thecarbonation/serpentinization reaction products were assessed. Forinstance, with respect to the ore composition, the mass, mineralogy, andgeochemical composition of the bulk rock were determined by x-ray powderdiffraction (XRD) to evaluate the abundance of relevant constituents(e.g., fayalite, ferrosilite, FeO, MgO, and CaO).

In the rock preparation phase, an ultramafic aggregate material thatincluded mostly lightly crushed rock of approximately 1.0 cm in sizewere collected from four active quarries (namely, two quarries inPennsylvania, one in Virginia, and one in Kentucky). The ultramaficaggregate material was disaggregated (i.e., lightly crushed/comminuted)initially with a rock hammer and then with a Spex Ball mill. Thepowdered material was then sieved using grates arranged and designed topass 150- and then 80-micron grains. This enabled experimentation to beconducted on at least two different grains sizes. Another material—ahomogenized olivine mineral—was also purchased from a scientificsupplier in California. This olivine material, which was homogenized forsize and composition, had a uniform particle size of approximately 100microns.

In the water preparation phase, two preparations were made. First, a lowoxygen fugacity, high pH water was obtained by adding sodium bicarbonateto tap water in order to adjust the pH of the water to be between about8.5 and about 11.1. As understood by those skilled in the art, oxygenfugacity (fO₂) is a measure of the amount of oxygen available to reactwith elements having multiple valence states—such as iron and carbon. Ahigh oxygen fugacity is indicative of a high chemical potential ofoxygen in the water. A lowered oxygen fugacity of water can be achievedin a variety of manners (e.g., by the use of low oxygen fugacity watersupply such as municipal wastewater, groundwater, mine water, or otherwastewater stream). One method for simply and reliably generating lowoxygen fugacity water utilizes a heated bed of copper filings at 125° C.through which the water is passed. In another method, a saline water wasobtained by adding salt (sodium chloride) to tap water to create salinesolutions ranging from 0.09 to 1.5%. In preparation for carbonmineralization experiments, the pH of the saline water was adjusted tobe between about 4.8 and about 6 using dilute HCl in a mixture ofdistilled water and a sodium acetate buffer.

For the reaction process, a batch reactor was designed and built toconduct the carbonation and serpentinization reactions in both batch andsequential configurations. All of the reactions were performed in thisclosed stainless steel reaction vessel as a “batch” reaction (i.e.,closed system). For each experiment, whole samples (approximately 250grams) were selected and sliced into two equally sliced approximately125 grams of raw material were placed in the gas-tight, stainless steelreaction vessels. In preparation for the introduction of water injectionto the vessel, low oxygen fugacity water with high pH (8.3-11.1 obtainedfrom using tap water plus sodium bicarbonate) and saline water (obtainedby adding NaCl to a concentration of 0.1 to 4.5 per mil). A heated bedof copper filings at 125° C. was utilized in our experimental setup toreduce oxygen fugacity. Separately for the CO₂ introduction stage, tapwater was lightly acidified using dilute HCl in a mixture of distilledwater and a sodium acetate buffer, mixed to 0.1 to 4.5 per mil NaCl atambient oxygen fugacity and sprayed onto powdered rock to provide a wetsurface (known to enhance CO₂ reactivity) for reactions.

In the first reaction phase, hydrogen generation was targeted. Beforethe introduction of water with low oxygen fugacity, the reactor wasevacuated using a mechanical rough pump to remove ambient oxygen. Next,water was introduced at room temperature and ambient atmosphericpressure. Initial pressure was recorded. Temperatures were increased to60, 100, 150, 200, 250, 300, and 400° C. with the temperature beingcontrolled by an external band heater and measured with an Omega K-wirethermocouple. At each step, gas phase pressure was measured on asampling port by monitoring with a standard Omega 0 to 100 psi pressuregauge and an aliquot of gas measured using a Stanford Research Systemsresidual gas analyzer (“quadrupole mass spectrometer”) and SRI gaschromatograph fitted with a thermocouple detector. The total pressure ofhydrogen was calculated by determining the product of the percentage ofhydrogen gas measured using the residual gas analyzer and/or gaschromatograph with the pressure compared to atmospheric pressure andassuming PV=nRT. The preliminary results indicated that the hydrogenkinetic rates (˜1.3 times) and total volume (1.8 times more at a giventemperature and composition) of hydrogen at thermodynamic equilibriumare improved by decreasing the grain size from 150 to 80 microns.

A second sequence of experiments focused on carbon sequestration in thepursuit of carbon neutral to carbon negative hydrogen. In this setup,the initial focus was on powdered rock and then the process was steppedup to utilize whole rock core plug samples. In both cases, the materialswere sprayed with water and placed into a stainless-steel reactionvessel and conducted as a “batch” reaction. Before the introduction ofwater, the reactor was evacuated using a mechanical rough pump to removeambient oxygen; later experiments demonstrated that the presence ofoxygen is not material to this reaction. Next, carbon dioxide (UHP CO₂and separately 4:1 CO₂ mixed with N₂) was introduced at room temperatureand at an initial pressure of 2 atmospheres (above atmosphericpressure). Next, the temperatures were increased to 100, 150, 200, 250,300, and 400° C. (controlled by an external band heater and measuredwith thermocouple). At each step, gas phase pressure was measured at asampling port by monitoring with a standard Omega 0 to 100 psi pressuregauge and an aliquot of gas measured using a Stanford Research Systemsresidual gas analyzer (“quadrupole mass spectrometer”) and SRI gaschromatograph fitted with a thermocouple detector. The total pressure ofhydrogen was calculated by determining the product of the percentage ofhydrogen gas measured using the residual gas analyzer and/or gaschromatograph with the pressure compared to atmospheric pressure andassuming PV=nRT. As a next step in this process, pressure was increasedto 5, 10, 25, and 50 bars of CO₂ measured using on-tank CO₂ pressuregauges. In the subsurface, significantly higher pressures can beachieved, but were not feasible in our current experimental setup;increased pressures would enhance the rate of the reaction. At eachstep, the gas phase pressure was measured on a sampling port attached toan expansion volume to reduce pressure and monitored using a standardOmega 0 to 100 psi pressure gauge and an aliquot of gas measured using aStanford Research Systems residual gas analyzer (“quadrupole massspectrometer”) and SRI gas chromatograph fitted with a thermocoupledetector. The total pressure of hydrogen was calculated by determiningthe product of the percentage of hydrogen gas measured using theresidual gas analyzer and/or gas chromatograph with the pressurecompared to atmospheric pressure and assuming PV=nRT. CO₂ sequestrationkinetics also improved with smaller grain sizes (˜1.8 times). The samesystematic experimental design will utilize super-critical CO₂.Following the experiments, the pieces of each sample (both first andsecond) were compared under optical microscopy to identifymineralization and evaluate porosity.

Following the hydrogen generation experiments, magnetite, brucite, andserpentine and the “pre-concentration” of an Mg-rich Mg-silica phase inthe whole rock was identified. The new material was subjected to theoptimized carbon sequestration experimental design. At each temperaturestep the pressure from the injected CO₂ decreased more significantlyindicating faster kinetic rates of CO₂ sequestration (3.6 times fasterdecrease was observed between 50 and 400° C. over the course of 18 hoursin the batch experiment. Following the experiments, the pieces of eachsample (both first and second) were compared under optical microscopy toidentify mineralization and evaluate porosity. The kinetic rates ofreactions improve (˜1.4 times) as hydrogen generation and CO₂-drivencomminution helped facilitate the further breakdown of the rock.

Following the sequential reactions, the mass, mineralogy, andgeochemical composition of the bulk rock were determined by XRD toevaluate the abundance of relevant constituents (e.g., fayalite,ferrosilite, FeO, MgO, CaO). It was observed that the abundance ofmagnesite and calcite were significantly (1.4 times) higher in thesequential reaction than when the reaction was done without firstinitiating hydrogen generation. Prior to initiation of the experiment,the first piece was evaluated using optical microscopy to identifymineral distribution, fractures, and pore space and compared to samplesfollowing treatment. The first piece of each sample was placed into thereaction chamber in gas-tight, stainless steel reaction vessels. Thesecond piece of each sample was used as a control for comparison.

Green (Carbon Negative) Hydrogen

As noted previously, sequestration of the carbon in the carbon dioxidewas targeted through carbonation reactions. The formation of magnesite(magnesium carbonate) and calcite (calcium carbonate) by “water-rock”serpentinization reactions using injected CO₂ and water into mafic orultramafic rock (in situ) provides an economic, scalable, and permanent(i.e., mineralized) form of carbon sequestration. The invention ofcarbon sequestration associated with in situ engineered hydrogengeneration is a two stage process that includes: 1) first, the removalof the Fe-rich Fe-silicate (or potentially Fe-sulfide) phases through insitu engineered hydrogen generation utilizing serpentinization reactionsunder optimized conditions, thereby increasing the thermochemical driverfor carbonation reactions; 2) the mixture and injection of water and CO₂under optimized conditions (pH of 4.4-6 under atmospheric (oxidizing)conditions) to chemically break down the Mg-rich and Ca-Rich silicateportions of mafic and ultramafic rocks at temperatures of 100-400° C. ata pressure in excess of ˜50 bars to produce magnesite (magnesiumcarbonate) and calcite (calcium carbonate). This process is donesequentially in optimized conditions that enable, and enhance, theproduction of magnesite and calcite while minimizing the formation ofaccessory/competitive phases and following the formation of enhancedporosity, permeability, and fracture intensity achieved by thesequential reaction.

CONCLUSION

Many modifications and other embodiments of the inventions set forthherein will come to mind to one skilled in the art to which theseinventions pertain having the benefit of the teachings presented in theforegoing descriptions and the associated drawings. Therefore, it is tobe understood that the inventions are not to be limited to the specificembodiments disclosed and that modifications and other embodiments areintended to be included within the scope of the appended claims.Moreover, although the foregoing descriptions and the associateddrawings describe example embodiments in the context of certain examplecombinations of elements and/or functions, it should be appreciated thatdifferent combinations of elements and/or functions may be provided byalternative embodiments without departing from the scope of the appendedclaims. In this regard, for example, different combinations of elementsand/or functions than those explicitly described above are alsocontemplated as may be set forth in some of the appended claims.Although specific terms are employed herein, they are used in a genericand descriptive sense only and not for purposes of limitation.

What is claimed is:
 1. A method of producing hydrogen gas from ageological formation comprising mafic igneous rock, ultramafic igneousrock, or a combination thereof, the method comprising: providing awellbore that at least partially traverses the geological formation, thewellbore providing a pathway for injection of fluids into the geologicalformation and recovery of fluids therefrom; injecting a water-basedstimulant through the pathway provided by the wellbore and into contactwith reactive surfaces of the geological formation; and recovering afluid composition comprising hydrogen gas from the wellbore via thepathway.
 2. The method of claim 1, further comprising: hydraulicallyfracturing the geological formation by pumping the water-based stimulantat high pressure through the wellbore and into the geological formation.3. The method of claim 1, wherein the water-based stimulant does notinclude carbon dioxide.
 4. The method of claim 1, wherein thewater-based stimulant includes dihydrogen sulfide.
 5. The method ofclaim 1, wherein the water-based stimulant has an oxygen fugacity with anegative Eh value, or wherein the water-based stimulant has a salinityof about 0.1 to 4.5 per mil sodium chloride.
 6. The method of claim 1,wherein the water-based stimulant that is injected into the pathway hasa pH of between about 8.3 and about 11.1; wherein pressure proximate tothe reactive surfaces of the geological formation is in excess of aboutone atmosphere and below a lithostatic pressure of the geologicalformation, or wherein the reactive surfaces of the geological formationhave a temperature of between about 60° C. and about 260° C.
 7. Themethod of claim 1, wherein the reactive surfaces of the geologicalformation have a temperature above about 260° C., and wherein the methodfurther comprises minimizing interaction of carbon dioxide with thereactive surfaces of the geological formation during injection of thewater-based stimulant.
 8. The method of claim 1, wherein the reactivesurfaces of the geological formation comprise one or more of fayalite,ferrosilite, or a combination thereof.
 9. The method of claim 1, whereinthe fluid composition recovered from the wellbore further comprises oneor more redox-sensitive components from the geological formation, andwherein the method further comprises separating the one or moreredox-sensitive components from the fluid composition recovered from thewellbore.
 10. The method of claim 1, further comprising: after the fluidcomposition is recovered, injecting carbon dioxide through the pathwayprovided by the wellbore and into the geological formation, whereinreaction of at least a portion of the carbon dioxide with one or more ofmafic or ultramafic rocks in the geological formation generates at leastmagnesium carbonate or calcium carbonate.
 11. The method of claim 10,wherein injecting the carbon dioxide through the pathway provided by thewellbore comprises injecting a mixture of water and carbon dioxidethrough the pathway provided by the wellbore and into the geologicalformation.
 12. The method of claim 11, wherein the mixture of water andcarbon dioxide has a pH of between about 4.8 and about 6.5, wherein themixture of water and carbon dioxide has a salinity of between 0.1 to 4.5per mil sodium chloride, wherein the mixture of water and carbon dioxidecontains nitrogen, dihydrogen sulfide, methane, or other trace gases,wherein the carbon dioxide is injected into the geological formation ata pressure of between one bar and a lithostatic pressure of thegeological formation, or wherein the carbon dioxide that is injectedinto the geological formation comprises supercritical carbon dioxide ora mixture of supercritical carbon dioxide and other fluids.
 13. Anapparatus for producing hydrogen gas from a geological formationcomprising mafic igneous rock, ultramafic igneous rock, or a combinationthereof, the apparatus comprising: means for providing a pathway forinjection of fluids into the geological formation and recovery of fluidstherefrom; means for injecting a water-based stimulant through thepathway and into contact with reactive surfaces of the geologicalformation; and means for recovering a fluid composition comprisinghydrogen gas via the pathway.
 14. A system to produce hydrogen gas froma geological formation comprising mafic igneous rock, ultramafic igneousrock, or a combination thereof or to sequester carbon dioxide in situ inthe geological formation, the system comprising: a wellbore that atleast partially traverses the geological formation; a source ofwater-based stimulant configurable to be in fluid communication with thewellbore to allow the water-based stimulant to pass to the geologicalformation through a pathway defined at least partially by the wellbore;a fluid containment device positioned about an upper portion of thewellbore, the fluid containment device having one or more outletsthrough which a fluid composition containing hydrogen gas may berecovered from the wellbore; and a source of carbon dioxide configurableto be in fluid communication with the wellbore to allow the carbondioxide to pass to the geological formation through the pathway definedat least partially by the wellbore.
 15. The system of claim 14, furthercomprising a pipeline connected to the one or more outlets of the fluidcontainment device to output the fluid composition containing hydrogengas that passes through the fluid containment device from the wellbore.16. The system of claim 14, further comprising a fluid storage vesselconnected to the one or more outlets of the fluid containment device tostore the fluid composition containing hydrogen gas that passes throughthe fluid containment device from the wellbore.
 17. The system of claim14, wherein the fluid containment device is a wellhead.
 18. The systemof claim 14, wherein the source of carbon dioxide is configurable toprovide the carbon dioxide to the wellbore at a pressure of between oneatmosphere and a lithostatic pressure of the geological formation. 19.The system of claim 14, wherein the water-based stimulant does notinclude carbon dioxide.
 20. The system of claim 15, wherein thewater-based stimulant has an oxygen fugacity with a negative Eh value,wherein the water-based stimulant has a salinity of between about 0.1 to4.5 per mil sodium chloride, or wherein the water-based stimulant has apH of between about 8.3 and about 11.1.